System and method for performing downhole stimulation operations
A system and method for performing stimulation operations at a wellsite having a subterranean formation with of a reservoir therein is provided. The method involves generating a plurality of quality indicators from a plurality of logs, and combining the plurality of quality indicators to form a composite quality indicator. The plurality of stress blocks may then be merged using diversion criterion. The composite quality indicator may be combined with the merged stress blocks to form a combined stress and composite quality indicator, the combined stress and composite quality indicator comprising a plurality of blocks with boundaries therebetween. The method may further comprise defining stages along the combined stress and composite quality indicator based on the diverter-assisted stage classifications; and selectively positioning perforations in select stages based on the diverter-assisted stage classifications thereon.
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This application is a continuation application of, and claims the benefit of priority to U.S. patent application Ser. No. 14/101,028 filed on Dec. 9, 2013, which is a continuation-in-part of, and claims the benefit of priority to, U.S. Patent Application Pub. No. 2012/0185225, filed on Dec. 28, 2011, and entitled SYSTEM AND METHOD FOR PERFORMING DOWNHOLE STIMULATION OPERATIONS, which claims priority to U.S. Pat. No. 8,412,500, issued on Apr. 2, 2013, and entitled SIMULATIONS FOR HYDRAULIC FRACTURING TREATMENTS AND METHODS OF FRACTURING NATURALLY FRACTURED FORMATION, which claims priority to U.S. Provisional Application No. 60/887,008, filed on Jan. 29, 2007, and entitled METHOD FOR HYDRAULIC FRACTURING TREATMENT IN NATURALLY FRACTURED FORMATION; this application also claims benefit of priority to U.S. Provisional Application No. 61/464,134, filed on Feb. 28, 2011, and U.S. Provisional Application No. 61/460,372, filed on Dec. 30, 2010, entitled INTEGRATED RESERVOIR CENTRIC COMPLETION AND STIMULATION DESIGN METHODS; the entire contents of each are hereby incorporated by reference herein in their entirety.BACKGROUND
The present disclosure relates to techniques for performing oilfield operations. More particularly, the present disclosure relates to techniques for performing stimulation operations, such as perforating, injecting, and/or fracturing, a subterranean formation having at least one reservoir therein. The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
Oilfield operations may be performed to locate and gather valuable downhole fluids, such as hydrocarbons. Oilfield operations may include, for example, surveying, drilling, downhole evaluation, completion, production, stimulation, and oilfield analysis. Surveying may involve seismic surveying using, for example, a seismic truck to send and receive downhole signals. Drilling may involve advancing a downhole tool into the earth to form a wellbore. Downhole evaluation may involve deploying a downhole tool into the wellbore to take downhole measurements and/or to retrieve downhole samples. Completion may involve cementing and casing a wellbore in preparation for production. Production may involve deploying production tubing into the wellbore for transporting fluids from a reservoir to the surface. Stimulation may involve, for example, perforating, fracturing, injecting, and/or other stimulation operations, to facilitate production of fluids from the reservoir.
Oilfield analysis may involve, for example, evaluating information about the wellsite and the various operations, and/or performing well planning operations. Such information may be, for example, petrophysical information gathered and/or analyzed by a petrophysicist; geological information gathered and/or analyzed by a geologist; or geophysical information gathered and/or analyzed by a geophysicist. The petrophysical, geological and geophysical information may be analyzed separately with dataflow therebetween being disconnected. A human operator may manually move and analyze the data using multiple software and tools. Well planning may be used to design oilfield operations based on information gathered about the wellsite.SUMMARY
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
The techniques disclosed herein relate to stimulation operations involving staging design. In an exemplary embodiment of the present disclosure, the method may involve generating a plurality of quality indicators from a plurality of logs, and combining the plurality of quality indicators to form a composite quality indicator. The composite quality indicator may be combined with a stress log to form a combined stress and composite quality indicator, the combined stress and composite quality indicator comprising a plurality of blocks with boundaries therebetween. The method may further comprise identifying classifications for the plurality of blocks; defining stages along the combined stress and composite quality indicator based on the classifications; and selectively positioning perforations in select stages based on the classifications thereon.
Embodiments of the method and system for performing a downhole stimulation operation are described with reference to the following figures. Like reference numerals are intended to refer to similar elements for consistency. For purposes of clarity, not every component may be labeled in every drawing.
The description that follows includes exemplary systems, apparatuses, methods, and instruction sequences that embody techniques of the subject matter herein. However, it is understood that the described embodiments may be practiced without these specific details.
The present disclosure relates to design, implementation and feedback of stimulation operations performed at a wellsite. The stimulation operations may be performed using a reservoir centric, integrated approach. These stimulation operations may involve integrated stimulation design based on multi-disciplinary information (e.g., used by a petrophysicist, geologist, geomechanicist, geophysicist and reservoir engineer), multi-well applications, and/or multi-stage oilfield operations (e.g., completion, stimulation, and production). Some applications may be tailored to unconventional wellsite applications (e.g., tight gas, shale, carbonate, coal, etc.), complex wellsite applications (e.g., multi-well), and various fracture models (e.g., conventional planar bi-wing fracture models for sandstone reservoirs or complex network fracture models for naturally fractured low permeability reservoirs), and the like. As used herein unconventional reservoirs relate to reservoirs, such as tight gas, sand, shale, carbonate, coal, and the like, where the formation is not uniform or is intersected by natural fractures (all other reservoirs are considered conventional).
The stimulation operations may also be performed using optimization, tailoring for specific types of reservoirs (e.g., tight gas, shale, carbonate, coal, etc.), integrating evaluations criteria (e.g., reservoir and completion criteria), and integrating data from multiple sources. The stimulation operations may be performed manually using conventional techniques to separately analyze dataflow, with separate analysis being disconnected and/or involving a human operator to manually move data and integrate data using multiple software and tools. These stimulation operations may also be integrated, for example, streamlined by maximizing multi-disciplinary data in an automated or semi-automated manner.
In response to the received sound vibration(s) 112 representative of different parameters (such as amplitude and/or frequency) of the sound vibration(s) 112, the geophones 118 may produce electrical output signals containing data concerning the subsurface formation. The data received 120 may be provided as input data to a computer 122.1 of the seismic truck 106.1, and responsive to the input data, the computer 122.1 may generate a seismic and microseismic data output 124. The seismic data output 124 may be stored, transmitted or further processed as desired, for example by data reduction.
A surface unit 134 may be used to communicate with the drilling tools and/or offsite operations. The surface unit may communicate with the drilling tools to send commands to the drilling tools, and to receive data therefrom. The surface unit may be provided with computer facilities for receiving, storing, processing, and/or analyzing data from the operation. The surface unit may collect data generated during the drilling operation and produce data output 135 which may be stored or transmitted. Computer facilities, such as those of the surface unit, may be positioned at various locations about the wellsite and/or at remote locations.
Sensors (S), such as gauges, may be positioned about the oilfield to collect data relating to various operations as described previously. As shown, the sensor (S) may be positioned in one or more locations in the drilling tools and/or at the rig to measure drilling parameters, such as weight on bit, torque on bit, pressures, temperatures, flow rates, compositions, rotary speed and/or other parameters of the operation. Sensors (S) may also be positioned in one or more locations in the circulating system.
The data gathered by the sensors may be collected by the surface unit and/or other data collection sources for analysis or other processing. The data collected by the sensors may be used alone or in combination with other data. The data may be collected in one or more databases and/or transmitted on or offsite. All or select portions of the data may be selectively used for analyzing and/or predicting operations of the current and/or other wellbores. The data may be historical data, real time data or combinations thereof. The real time data may be used in real time, or stored for later use. The data may also be combined with historical data or other inputs for further analysis. The data may be stored in separate databases, or combined into a single database.
The collected data may be used to perform analysis, such as modeling operations. For example, the seismic data output may be used to perform geological, geophysical, and/or reservoir engineering analysis. The reservoir, wellbore, surface and/or processed data may be used to perform reservoir, wellbore, geological, and geophysical or other simulations. The data outputs from the operation may be generated directly from the sensors, or after some preprocessing or modeling. These data outputs may act as inputs for further analysis.
The data may be collected and stored at the surface unit 134. One or more surface units may be located at the wellsite, or connected remotely thereto. The surface unit may be a single unit, or a complex network of units used to perform the necessary data management functions throughout the oilfield. The surface unit may be a manual or automatic system. The surface unit 134 may be operated and/or adjusted by a user.
The surface unit may be provided with a transceiver 137 to allow communications between the surface unit and various portions of the current oilfield or other locations. The surface unit 134 may also be provided with or functionally connected to one or more controllers for actuating mechanisms at the wellsite 100. The surface unit 134 may then send command signals to the oilfield in response to data received. The surface unit 134 may receive commands via the transceiver or may itself execute commands to the controller. A processor may be provided to analyze the data (locally or remotely), make the decisions and/or actuate the controller. In this manner, operations may be selectively adjusted based on the data collected. Portions of the operation, such as controlling drilling, weight on bit, pump rates or other parameters, may be optimized based on the information. These adjustments may be made automatically based on computer protocol, and/or manually by an operator. In some cases, well plans may be adjusted to select optimum operating conditions, or to avoid problems.
The wireline tool 106.3 may be operatively connected to, for example, the geophones 118 and the computer 122.1 of the seismic truck 106.1 of
Sensors (S), such as gauges, may be positioned about the wellsite 100 to collect data relating to various operations as described previously. As shown, the sensor (S) is positioned in the wireline tool 106.3 to measure downhole parameters which relate to, for example porosity, permeability, fluid composition and/or other parameters of the operation.
Sensors (S), such as gauges, may be positioned about the oilfield to collect data relating to various operations as described previously. As shown, the sensor (S) may be positioned in the production tool 106.4 or associated equipment, such as the Christmas tree 129, gathering network, surface facilities and/or the production facility, to measure fluid parameters, such as fluid composition, flow rates, pressures, temperatures, and/or other parameters of the production operation.
While only simplified wellsite configurations are shown, it will be appreciated that the oilfield or wellsite 100 may cover a portion of land, sea and/or water locations that hosts one or more wellsites. Production may also include injection wells (not shown) for added recovery or for storage of hydrocarbons, carbon dioxide, or water, for example. One or more gathering facilities may be operatively connected to one or more of the wellsites for selectively collecting downhole fluids from the wellsite(s).
It should be appreciated that
The oilfield configuration of
The respective graphs of
Wellbore 336.1 extends from rig 308.1, through unconventional reservoirs 304.1-304.3. Wellbores 336.2 and 336.3 extend from rigs 308.2 and 308.3, respectfully to unconventional reservoir 304.4. As shown, unconventional reservoirs 304.1-304.3 are tight gas sand reservoirs and unconventional reservoir 304.4 is a shale reservoir. One or more unconventional reservoirs (e.g., such as tight gas, shale, carbonate, coal, heavy oil, etc.) and/or conventional reservoirs may be present in a given formation.
The stimulation operations of
Downhole tool 306.1 is positioned in vertical wellbore 336.1 adjacent tight gas sand reservoirs 304.1 for taking downhole measurements. Packers 307 are positioned in the wellbore 336.1 for isolating a portion thereof adjacent perforations 338.2. Once the perforations are formed about the wellbore fluid may be injected through the perforations and into the formation to create and/or expand fractures therein to stimulate production from the reservoirs.
Reservoir 304.4 of formation 302.2 has been perforated and packers 307 have been positioned to isolate the wellbore 336.2 about the perforations 338.3-338.5. As shown in the horizontal wellbore 336.2, packers 307 have been positioned at stages St1 and St2 of the wellbore. As also depicted, wellbore 304.3 may be an offset (or pilot) well extended through the formation 302.2 to reach reservoir 304.4. One or more wellbores may be placed at one or more wellsites. Multiple wellbores may be placed as desired.
Fractures may be extended into the various reservoirs 304.1-304.4 for facilitating production of fluids therefrom. Examples of fractures that may be formed are schematically shown in
Referring back to
A stimulation tool 350 may be provided as part of the surface unit 334 or other portions of the wellsite for performing stimulation operations. For example, information generated during one or more of the stimulation operations may be used in well planning for one or more wells, one or more wellsites and/or one or more reservoirs. The stimulation tool 350 may be operatively linked to one or more rigs and/or wellsites, and used to receive data, process data, send control signals, etc., as will be described further herein. The stimulation tool 350 may include a reservoir characterization unit 363 for generating a mechanical earth model (MEM), a stimulation planning unit 365 for generating stimulation plans, an optimizer 367 for optimizing the stimulation plans, a real time unit 369 for optimizing in real time the optimized stimulation plan, a control unit 368 for selectively adjusting the stimulation operation based on the real time optimized stimulation plan, an updater 370 for updating the reservoir characterization model based on the real time optimized stimulation plan and post evaluation data, and a calibrator 372 for calibrating the optimized stimulation plan as will be described further herein. The stimulation planning unit 365 may include a staging design tool 381 for performing staging design, a stimulation design tool 383 for performing stimulation design, a production prediction tool 385 for prediction production and a well planning tool 387 for generating well plans.
Wellsite data used in the stimulation operation may range from, for example, core samples to petrophysical interpretation based on well logs to three dimensional seismic data (see, e.g.,
Stimulation operations for conventional and unconventional reservoirs may be performed based on knowledge of the reservoir. Reservoir characterization may be used, for example, in well planning, identifying optimal target zones for perforation and staging, design of multiple wells (e.g., spacing and orientation), and geomechanical models. Stimulation designs may be optimized based on a resulting production prediction. These stimulation designs may involve an integrated reservoir centric workflow which include design, real time (RT), and post treatment evaluation components. Well completion and stimulation design may be performed while making use of multi-disciplinary wellbore and reservoir data.
The pre-stimulation evaluation 445 involves reservoir characterization 460 and generating a three-dimensional mechanical earth model (MEM) 462. The reservoir characterization 460 may be generated by integrating information, such as the information gathered in
Reservoir characterization 460 may involve capturing a variety of information, such as data associated with the underground formation and developing one or more models of the reservoir. The information captured may include, for example, stimulation information, such as reservoir (pay) zone, geomechanical (stress) zone, natural fracture distribution. The reservoir characterization 460 may be performed such that information concerning the stimulation operation is included in pre-stimulation evaluations. Generating the MEM 462 may simulate the subterranean formation under development (e.g., generating a numerical representation of a state of stress and rock mechanical properties for a given stratigraphic section in an oilfield or basin).
Conventional geomechanical modeling may be used to generate the MEM 462. Examples of MEM techniques are provided in US Patent Application No. 2009/0187391. The MEM 462 may be generated by information gathered using, for example, the oilfield operations of
The generated MEM 462 may be used as an input in performing stimulation planning 447. The 3D MEM may be constructed to identify potential drilling wellsites. In one embodiment, when the formation is substantially uniform and is substantially free of major natural fractures and/or high-stress barriers, it can be assumed that a given volume of fracturing fluid pumped at a given rate over a given period of time will generate a substantially identical fracture network in the formation. Core samples, such as those shown in
The stimulation planning 447 may involve well planning 465, staging design 466, stimulation design, 468 and production prediction 470. In particular, the MEM 462 may be an input to the well planning 465 and/or the staging design 466 and stimulation design 468. Some embodiments may include semi-automated methods to identify, for example, well spacing and orientation, multistage perforation design and hydraulic fracture design. To address a wide variation of characteristics in hydrocarbon reservoirs, some embodiments may involve dedicated methods per target reservoir environments, such as, but not limited to, tight gas formations, sandstone reservoirs, naturally fractured shale reservoirs, or other unconventional reservoirs.
The stimulation planning 447 may involve a semi-automated method used to identify potential drilling wellsites by partitioning underground formations into multiple set of discrete intervals, characterizing each interval based on information such as the formation's geophysical properties and its proximity to natural fractures, then regrouping multiple intervals into one or multiple drilling wellsites, with each wellsite receiving a well or a branch of a well. The spacing and orientation of the multiple wells may be determined and used in optimizing production of the reservoir. Characteristics of each well may be analyzed for stage planning and stimulation planning. In some cases, a completion advisor may be provided, for example, for analyzing vertical or near vertical wells in tight-gas sandstone reservoir following a recursive refinement workflow.
Well planning 465 may be performed to design oilfield operations in advance of performing such oilfield operations at the wellsite. The well planning 465 may be used to define, for example, equipment and operating parameters for performing the oilfield operations. Some such operating parameters may include, for example, perforating locations, operating pressures, stimulation fluids, and other parameters used in stimulation. Information gathered from various sources, such as historical data, known data, and oilfield measurements (e.g., those taken in
The well planning 465 and/or MEM 462 may also be used as inputs into the staging design 466. Reservoir and other data may be used in the staging design 466 to define certain operational parameters for stimulation. For example, staging design 466 may involve defining boundaries in a wellbore for performing stimulation operations as described further herein. Examples of staging design are described in US Patent Application No. 2011/0247824. Staging design may be an input for performing stimulation design 468.
Stimulation design defines various stimulation parameters (e.g., perforation placement) for performing stimulation operations. The stimulation design 468 may be used, for example, for fracture modeling. Examples of fracture modeling are described in US Patent Application No. 2008/0183451, 2006/0015310 and PCT Publication No. WO2011/077227. Stimulation design may involve using various models to define a stimulation plan and/or a stimulation portion of a well plan.
Stimulation design may integrate 3D reservoir models (formation models), which can be a result of seismic interpretation, drilling geo-steering interpretation, geological or geomechanical earth model, as a starting point (zone model) for completion design. For some stimulation designs, a fracture modeling algorithm may be used to read a 3D MEM and run forward modeling to predict fracture growth. This process may be used so that spatial heterogeneity of a complex reservoir may be taken into account in stimulation operations. Additionally, some methods may incorporate spatial X-Y-Z sets of data to derive an indicator, and then use the indicator to place and/or perform a wellbore operation, and in some instance, multiple stages of wellbore operations as will be described further herein.
Stimulation design may use 3D reservoir models for providing information about natural fractures in the model. The natural fracture information may be used, for example, to address certain situations, such as cases where a hydraulically induced fracture grows and encounters a natural fracture (see, e.g.,
Microseismic mapping may also be used in stimulation design to understand complex fracture growth. The occurrence of complex fracture growth may be present in unconventional reservoirs, such as shale reservoirs. The nature and degree of fracture complexity may be analyzed to select an optimal stimulation design and completion strategy. Fracture modeling may be used to predict the fracture geometry that can be calibrated and the design optimized based on real time Microseismic mapping and evaluation. Fracture growth may be interpreted based on existing hydraulic fracture models. Some complex hydraulic fracture propagation modeling and/or interpretation may also be performed for unconventional reservoirs (e.g., tight gas sand and shale) as will be described further herein. Reservoir properties, and initial modeling assumptions may be corrected and fracture design optimized based on microseismic evaluation.
Examples of complex fracture modeling are provided in SPE paper 140185, the entire contents of which is hereby incorporated by reference. This complex fracture modeling illustrates the application of two complex fracture modeling techniques in conjunction with microseismic mapping to characterize fracture complexity and evaluate completion performance. The first complex fracture modeling technique is an analytical model for estimating fracture complexity and distances between orthogonal fractures. The second technique uses a gridded numerical model that allows complex geologic descriptions and evaluation of complex fracture propagation. These examples illustrate how embodiments may be utilized to evaluate how fracture complexity is impacted by changes in fracture treatment design in each geologic environment. To quantify the impact of changes in fracture design using complex fracture models despite inherent uncertainties in the MEM and “real” fracture growth, microseismic mapping and complex fracture modeling may be integrated for interpretation of the microseismic measurements while also calibrating the complex stimulation model. Such examples show that the degree of fracture complexity can vary depending on geologic conditions.
Production prediction 470 may involve estimating production based on the well planning 465, staging design 466 and stimulation design 468. The result of stimulation design 468 (i.e. simulated fracture models and input reservoir model) can be carried over to a production prediction workflow, where a conventional analytical or numerical reservoir simulator may operate on the models and predicts hydrocarbon production based on dynamic data. The preproduction prediction 470 can be useful, for example, for quantitatively validating the stimulation planning 447 process.
Part or all of the stimulation planning 447 may be iteratively performed as indicated by the flow arrows. As shown, optimizations may be provided after the staging design 466, stimulation design 468, and production prediction 470, and may be used as a feedback to optimize 472 the well planning 465, the staging design 466 and/or the stimulation design 468. The optimizations may be selectively performed to feedback results from part or all of the stimulation planning 447 and iterate as desired into the various portions of the stimulation planning process and achieve an optimized result. The stimulation planning 447 may be manually carried out, or integrated using automated optimization processing as schematically shown by the optimization 472 in feedback loop 473.
Various portions of the stimulation operation may be designed and/or optimized. Examples of optimizing fracturing are described, for example, in U.S. Pat. No. 6,508,307. In another example, financial inputs, such as fracture costs which may affect operations, may also be provided in the stimulation planning 447. Optimization may be performed by optimizing stage design with respect to production while taking into consideration financial inputs. Such financial inputs may involve costs for various stimulation operations at various stages in the wellbore as depicted in
Referring back to
When multiple wells are planned or drilled, simulations can be repeated for each well so that each well has a staging plan, perforation plan, and/or stimulation plan. Thereafter, multi-well planning can be adjusted if necessary. For example, if a fracture stimulation in one well indicates that a stimulation result will overlap a nearby well with a planned perforation zone, the nearby well and/or the planned perforation zone in the nearby well can be eliminated or redesigned. On the contrary, if a simulated fracture treatment cannot penetrate a particular area of the formation, either because the pay zone is simply too far away for a first fracture well to effectively stimulate the pay zone or because the existence of a natural fracture or high-stress barrier prevents the first fracture well from effectively stimulating the pay zone, a second well/branch or a new perforation zone may be included to provide access to the untreated area. The 3D reservoir model may take into account simulation models and indicate a candidate location to drill a second well/branch or to add an additional perforation zone. A spatial X′-Y′-Z′ location may be provided for the oilfield operator's ease of handling.
Post Planning Stimulation Operations
Embodiments may also include real time treatment optimization (or post job workflows) 451 for analyzing the stimulation operation and updating the stimulation plan during actual stimulation operations. The real time treatment optimization 451 may be performed during implementation of the stimulation plan at the wellsite (e.g., performing fracturing, injecting or otherwise stimulating the reservoir at the wellsite). The real time treatment optimization may involve calibration tests 449, executing 448 the stimulation plan generated in stimulation planning 447, and real time oilfield stimulation 455.
Calibration tests 449 may optionally be performed by comparing the result of stimulation planning 447 (i.e. simulated fracture models) with the observed data. Some embodiments may integrate calibration into the stimulation planning process, perform calibrations after stimulation planning, and/or apply calibrations in real-time execution of stimulation or any other treatment processes. Examples of calibrations for fracture or other stimulation operations are described in US Patent Application No. 2011/0257944, the entire contents of which are hereby incorporated by reference.
Based on the stimulation plan generated in the stimulation planning 447 (and calibration 449 if performed), the oilfield stimulation 445 may be executed 448. Oilfield stimulation 455 may involve real time measurement 461, real time interpretation 463, real time stimulation design 465, real time production 467 and real time control 469. Real time measurement 461 may be performed at the wellsite using, for example, the sensors S as shown in
Real time interpretation 463 may be performed on or off site based on the data collected. Real time stimulation design 465 and production prediction 467 may be performed similar to the stimulation design 468 and production prediction 470, but based on additional information generated during the actual oilfield stimulation 455 performed at the wellsite. Optimization 471 may be provided to iterate over the real time stimulation design 465 and production prediction 467 as the oilfield stimulation progresses. Real time stimulation 455 may involve, for example, real time fracturing. Examples of real time fracturing are described in US Patent Application No. 2010/0307755, the entire contents of which are hereby incorporated by reference.
Real time control 469 may be provided to adjust the stimulation operation at the wellsite as information is gathered and an understanding of the operating conditions is gained. The real time control 469 provides a feedback loop for executing 448 the oilfield stimulation 455. Real time control 469 may be executed, for example, using the surface unit 334 and/or downhole tools 306.1-306.4 to alter operating conditions, such as perforation locations, injection pressures, etc. While the features of the oilfield stimulation 455 are described as operating in real time, one or more of the features of the real time treatment optimization 451 may be performed in real time or as desired.
The information generated during the real time treatment optimization 451 may be used to update the process and feedback to the reservoir characterization 445. The design/model update 453 includes post treatment evaluation 475 and update model 477. The post treatment evaluation involves analyzing the results of the real time treatment optimization 451 and adjusting, as necessary, inputs and plans for use in other wellsites or wellbore applications.
The post treatment evaluation 475 may be used as an input to update the model 477. Optionally, data collected from subsequent drilling and/or production can be fed back to the reservoir characterization 445 (e.g., the 3D earth model) and/or stimulation planning 447 (e.g., well planning module 465). Information may be updated to remove errors in the initial modeling and simulation, to correct deficiencies in the initial modeling, and/or to substantiate the simulation. For example, spacing or orientation of the wells may be adjusted to account the newly developed data. Once the model is updated 477, the process may be repeated as desired. One or more wellsites, wellbores, stimulation operations or variations may be performed using the method 400.
In a given example, a stimulation operation may be performed by constructing a 3D model of a subterranean formation and performing a semi-automated method involving dividing the subterranean formation into a plurality of discrete intervals, characterizing each interval based on the subterranean formation's properties at the interval, grouping the intervals into one or more drilling sites, and drilling a well in each drilling site.
Tight Gas Sand Applications
An example stimulation design and downstream workflow useful for unconventional reservoirs involving tight gas sandstone (see, e.g., reservoirs 304.1-304.3 of
The log 500 (or 601) may correlate to a method 501 involving analyzing the log 500 to define (569) boundaries 568 at intervals along the log 500 based on the data provided. The boundaries 568 may be used to identify (571) pay zones 570 along the wellbore. A fracture unit 572 may be specified (573) along the wellbore. Staging design may be performed (575) to define stages 574 along the wellbore. Finally, perforations 576 may be designed (577) along locations in the stages 574.
A semi-automated method may be used to identify partitioning of a treatment interval into multiple sets of discrete intervals (multi-stages) and to compute a configuration of perforation placements, based on these inputs. Reservoir (petrophysical) information and completion (geomechanical) information may be factored into the model, simultaneously. Zone boundaries may be determined based on input logs. Stress logs may be used to define the zones. One can choose any other input log or a combination of logs which represents the reservoir formation.
Reservoir pay zones can be imported from an external (e.g., petrophysical interpretation) workflow. The workflow may provide a pay zone identification method based on multiple log cutoffs. In the latter case, each input log value (i.e. default logs) may include water saturation (Sw), porosity (Phi), intrinsic permeability (Kint) and volume of clay (Vcl), but other suitable logs can be used. Log values may be discriminated by their cutoff values. If all cutoff conditions are met, corresponding depth may be marked as a pay zone. Minimum thickness of a pay zone, KH (permeability multiplied by zone height) and PPGR (pore pressure gradient) cutoff conditions may be applied to eliminate poor pay zones at the end. These pay zones may be inserted into the stress based zone model. The minimum thickness condition may be examined to avoid creation of tiny zones. The pay zones may also be selected and the stress based boundary merged therein. In another embodiment, 3D zone models provided by the reservoir modeling process may be used as the base boundaries and the output zones, finer zones, may be inserted.
For each identified pay zones, a simple fracture height growth estimation computation based on a net pressure or a bottom hole treating pressure may be performed, and the overlapping pays combined to form a fracture unit (FracUnit). Stimulation stages may be defined based on one or more of the following conditions: minimum net height, maximum gross height and minimum distance between stages.
The set of FracUnits may be scanned, and possible combinations of consecutive FracUnits examined. Certain combinations that violate certain conditions may be selectively excluded. Valid combinations identified may act as staging scenarios. A maximum gross height (=stage length) may be variated and combinatory checks run repeatedly for each of the variations. Frequently occurring staging scenarios may be counted from a collection of all outputs to determine final answers. In some cases, no ‘output’ may be found because no single staging design may be ascertained that meets all conditions. In such case, the user can specify the priorities among input conditions. For example, maximum gross height may be met, and minimum distance between stage may be ignored to find the optimum solution.
Perforation locations, shot density and number of shots, may be defined based on a quality of pay zone if the stress variations within a stage are insignificant. If the stress variations are high, a limited entry method may be conducted to determine distribution of shots among fracture units. A user can optionally choose to use a limited entry method (e.g., stage by stage) if desired. Within each FracUnit, a location of perforation may be determined by a selected KH (permeability multiplied by perforation length).
A multi-stage completion advisor may be used for reservoir planning for a gas shale reservoir. Where a majority of producing wells are essentially horizontally drilled (or drilled deviated from a vertical borehole) an entire lateral section of a borehole may reside within a target reservoir formation (see, e.g., reservoir 304.4 of
In a given example, stimulation operations may be performed utilizing a partially automated method to identify best multistage perforation design in a wellbore. A near wellbore zone model may be developed based upon key characteristics, such as reservoir pay zone and geomechanical stress zone. A treatment interval may be partitioned into multiple set of discrete intervals, and a configuration of perforation placement in the wellbore may be computed. A stimulation design workflow including single or multi-layer planar fracture models may be utilized.
A completion advisor for a horizontal well penetrating formations of shale reservoirs is illustrated in
Other quality indicators, such as a completions quality indicator, may be formed in a similar manner using applicable logs (e.g., Young's modulus, Poisson's ratio, etc. for a completions log). Quality indicators, such as reservoir quality 802 and completion quality 801 may be combined (1346) to form a composite quality indicator 803 as shown in
Stress blocks may be adjusted to a desired size of blocks. For example, small stress blocks may be eliminated where an interval is less than a minimum stage length by merging it with an adjacent block to form a refined composite quality indicator 902. One of two neighboring blocks which has a smaller stress gradient difference may be used as a merging target. In another example, large stress blocks may be split where an interval is more than a maximum stage length to form another refined composite quality indicator 905.
As shown in
If a ‘BB’ block is large enough as in the quality indicator 1021, then the quality indicator may be shifted (1356) into its own stage as shown in the shifted quality indicator 1023. Additional constraints, such as hole deviation, natural and/or induced fracture presence, may be checked to make stage characteristics homogeneous.
As shown in
As shown in
Stress balancing may be performed to locate where the stress gradient values are similar (e.g. within 0.05 psi/ft) within a stage. For example, if the user input is 3 perforations per stage, a best (i.e. lowest stress gradient) location which meets conditions (e.g., where spacing between perforations and are within the range of stress gradient) may be searched. If not located, the search may continue for the next best location and repeated until it finds, for example, three locations to put three perforations.
If a formation is not uniform or is intersected by major natural fractures and/or high-stress barriers, additional well planning may be needed. In one embodiment, the underground formation may be divided into multiple sets of discrete volumes and each volume may be characterized based on information such as the formation's geophysical properties and its proximity to natural fractures. For each factor, an indicator such as “G” (Good), “B” (Bad), or “N” (Neutral) can be assigned to the volume. Multiple factors can then be synthesized together to form a composite indicator, such as “GG”, “GB”, “GN”, and so on. A volume with multiple “B”s indicates a location may be less likely to be penetrated by fracture stimulations. A volume with one or more “G”s may indicate a location that is more likely to be treatable by fracture stimulations. Multiple volumes can be grouped into one or more drilling wellsites, with each wellsite representing a potential location for receiving a well or a branch. The spacing and orientation of multiple wells can be optimized to provide an entire formation with sufficient stimulation. The process may be repeated as desired.
The method may also involve performing (1468) a calibration of the optimized stimulation plan (e.g., 449 of
One specific type of well operation is a diversion treatment. Hydraulic and acid fracturing of horizontal wells as well as multi-layered formations may require using diverting techniques in order to enable fracturing redirection between different zones. Examples of suitable diverting techniques may include the application of ball sealers, slurried benzoic acid flakes and/or removable/degradable particulates, as described in U.S. Patent Application Pub. No. 2012/0285692, the disclosure of which is incorporated by reference herein in its entirety. As well, other treatments may employ of diverting techniques.
Disclosed herein are diverter-assisted-staging algorithms for a well penetrating a subterranean formation. Separate algorithms may be used for vertical and horizontal wells. The diverter-assisted staging algorithm may include various semi-automated processes to identify the optimum multi-stage perforation and staging design for treatments using a diverter. As used herein, the term “diverter” refers to a material placed within a subterranean formation to partially or entirely plug a feature of the subterranean formation, such as, for example, a perforation or fracture of the formation. The term “diverter” should not be defined to include “bridge plugs” or any similar device, which are employed to isolate a specific section of a wellbore.
The staging algorithms utilize a variety of reservoir data that may be obtained both from the subterranean formation and/or the 3D geological model. The algorithms may also utilize petrophysical properties such as, for example, open hole and cased hole logs, borehole images, core data and 3D reservoir models to determine reservoir quality. Geomechanical properties such as, for example, in-situ rock stresses, modulus of elasticity, leak-off coefficient, Poisson's ratio of the wellbore may be used to determine fracture initiation, propagation, and containment within the target zones (completion quality).
For vertical wells, once the boundaries, reservoir (pay) zones, FracUnits are defined and the staging design is completed, the diverter's ability at overcoming stress variations may be incorporated into a perforation design to promote the distribution of the fracturing fluids, such as limited entry method, which is achieved by choosing perforation diameter and number of perforations such that the anticipated injection rate produces sufficient velocity though each perforation to create a pressure differential between the hydraulic fracture and the wellbore.
An example stimulation design and downstream workflow useful for unconventional reservoirs involving tight gas sandstone (see, e.g., reservoirs 304.1-304.3 of
A diverter-assisted completion advisor for a vertical well penetrating formations of shale reservoirs is illustrated in
The log 1500 (or 601) may correlate to a method 1501 involving analyzing the log 1500 to define (1569) boundaries 1568 at intervals along the log 1500 based on the data provided. The boundaries 1568 may be used to identify (1571) pay zones 1570 along the wellbore. A fracture unit 1572 may be specified (1573) along the wellbore. Staging design may be performed (1575) to define stages 1574 along the wellbore. Perforations 1576 may be designed (1577) along locations in the stages 1574. Finally, a diversion treatment may be designed (1579) along one or more of the locations in stages 1574. The diversion design should include a quantity of diverter such as, for example, the quantity or amount of diverter to plug a number of perforations in order to generate an additional pressure differential between the hydraulic fracture(s) and the wellbore required to divert fluid to other perforations. The diverter may be selected based upon information known to persons skilled in the art, with rules such as being able to plug the downhole features the induced fracture.
For horizontal wells, reservoir quality indicators and completion quality indicators are classified and combined in composite quality blocks, as discussed in further detail below. Generally, stress information may be used to generate stress blocks. Here stress may mean the computed fracture initiation or breakdown pressure derived from the in-situ stresses and wellbore properties. If the stress difference between blocks is lower than a threshold value defined by the pressure which is generated by the diverter, then the stress blocks are merged. The merged stress blocks and the composite quality index are combined to design stages and perforation clusters. Finally, the diverter enables adding a final step of selectively positioning the perforations.
A diverter-assisted-completion advisor for a horizontal well penetrating formations of shale reservoirs is illustrated in
Stress blocks may be adjusted to a desired size of blocks. For example, small stress blocks may be eliminated where an interval is less than a minimum stage length by merging it with an adjacent block to form a refined composite quality indicator 1606. One of two neighboring blocks which has a smaller stress gradient difference may be used as a merging target. In another example, large stress blocks may be split where an interval is more than a maximum stage length to form another refined composite quality indicator 1607.
Perforations can be located to impart a preferred direction to the sequence of clusters to be fractured (see
Alternatively, as shown in
In a reservoir with medium level of horizontal stress anisotropy, such as, for example, a first stage may initially open the low stress clusters creating bi-wing or low complexity fracture 2202 due to stress anisotropy. In brittle formations, the propagation of the bi-wing fractures 2202 can also cause parallel stress relief fractures 2206. Such bi-wing fractures 2202 are presented in
The induced fractures induce an altered stress field in the surrounding formation. The stress perpendicular to the fractures may change by a larger degree than the stress parallel to the fracture, thereby reducing the stress contrast. Stress anisotropy can be reduced or even reversed to facilitate openings of planes of weakness within the rock.
Pumping the diverter obstructs the fractures. A second part of pumping after diversion will initiate fracturing in the higher stress clusters in areas of the rock that would be altered by the stress shadow of the 1st stage. Those stress-altered regions have a lower, or inverted stress anisotropy and therefore the dilation of the existing natural fracture or shear failure of planes of weakness. Therefore these fractures would likely be more complex (i.e., for a complex fracture network 2302) giving a better connection with hydrocarbon remaining in the formation. See
An individual using the diverter-assisted completion advisor may decide to compare the results of the simulation with a diverter and without the diverter. Because the diverter enables merging stress blocks, the diverter assisted algorithm tends to show that the length of each section isolated with bridge plugs is in general longer than without diverter. The engineer may also chose a higher value of max stage length based on the simulation results.
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.
In a given example, a stimulation operation may be performed involving evaluating variability of reservoir properties and completion properties separately for a treatment interval in a wellbore penetrating a subterranean formation, partitioning the treatment interval into a set of contiguous intervals (both reservoir and completion properties may be similar within each partitioned treatment interval, designing a stimulation treatment scenario by using a set of planar geometric objects (discrete fracture network) to develop a 3D reservoir model, and combining natural fracture data with the 3D reservoir model to account heterogeneity of formation and predict hydraulic fracture progressions.
1. A method for staging a stimulation operation for a wellsite having a reservoir positioned in a subterranean formation, comprising:
- obtaining a log of at least a portion of a wellbore of the wellsite;
- defining a plurality of boundaries at one or more intervals along the log based on stimulation data;
- identifying a plurality of pay zones along the wellbore based on the plurality of boundaries;
- specifying one or more fracture units along the plurality of pay zones, wherein at least one fracture unit of the one or more fracture units comprises two or more pay zones of the plurality of pay zones, wherein specifying the one or more fracture units comprises: performing one or more height growth estimation calculations for the two or more pay zones of the plurality of pay zones; and determining whether the two or more pay zones of the plurality of pay zones overlap based on the one or more height growth estimation calculations;
- defining one or more stages along the one or more fracture units;
- designing a plurality of perforation locations based on the one or more stages;
- designing a diversion treatment configured to divert fluid from a first perforation location of the plurality of perforation locations to a second perforation location of the plurality of perforation locations;
- perforating the wellbore at a plurality of locations based on the first perforation location and the second perforation location; and
- executing the diversion treatment at the wellsite.
2. The method of claim 1, wherein obtaining the log comprises measuring at least one parameter along the at least a portion of the wellbore.
3. The method of claim 1, wherein the reservoir comprises a tight gas sand reservoir.
4. The method of claim 1, wherein the log comprises a resistivity log, a permeability log, a porosity log or any combination thereof.
5. The method of claim 1, wherein the log comprises a composite log formed from a plurality of logs.
6. The method of claim 1, wherein defining the one or more stages comprises defining the one or more stages based on a minimum net height, a maximum net height, a minimum distance between the one or more stages, or a combination thereof.
7. The method of claim 6, wherein defining the one or more stages comprises defining the one or more stages based on two or more of the minimum net height, the maximum net height, and the minimum distance between the one or more stages.
8. The method of claim 1, wherein specifying the one or more fracture units comprises:
- adjusting the two or more pay zones of the plurality of pay zones based on the one or more height growth estimation calculations to form two or more adjusted pay zones; and
- determining whether the two or more adjusted pay zones overlap.
9. The method of claim 1, wherein the diversion treatment comprises a quantity of a diverter.
10. The method of claim 9, wherein the quantity of diverter is sufficient to plug
- a first location of the plurality of locations such that fluid is diverted to a second location of the plurality of locations.
11. A system for staging a stimulation operation for a wellsite having a reservoir positioned in a subterranean formation, comprising:
- a downhole tool comprising one or more sensors configured to collect data regarding a wellbore of the wellsite, the reservoir, or both, wherein the downhole tool is configured to perforate the wellbore; and
- a stimulation tool configured to: receive the data from the one or more sensors; generate a log of at least a portion of the wellbore based on the data from the one or more sensors; define a plurality of boundaries at one or more intervals along the log based on the data; identify a plurality of pay zones along the wellbore based on the plurality of boundaries; specify one or more fracture units along the plurality of pay zones, wherein at least one fracture unit of the one or more fracture units comprises two or more pay zones of the plurality of pay zones, wherein the stimulation tool is configured to specific the one or more fractures by: performing one or more height growth estimation calculations for the two or more pay zones of the plurality of pay zones; and determining whether the two or more pay zones of the plurality of pay zones overlap based on the one or more height growth estimation calculations; define one or more stages along the one or more fracture units; design a plurality of perforation locations based on the one or more stages; design a diversion treatment configured to divert fluid from a first perforation location of the plurality of perforation locations to a second perforation location of the plurality of perforation locations; and send a command to cause the downhole tool to: perforate the wellbore at a plurality of locations based on the first perforation location and the second perforation location; and execute the diversion treatment in the subterranean formation.
12. The system of claim 11, wherein the log comprises a combined log having a resistivity log, a permeability log, a porosity log, or any combination thereof.
13. The system of claim 12, wherein the combined log comprises the resistivity log, the permeability log, and the porosity log.
14. The system of claim 11, wherein the stimulation tool is configured to:
- modify the plurality of perforation locations based on the data after the wellbore is perforated.
15. The system of claim 11, wherein the wellbore comprises a vertical wellbore.
16. A system for staging a stimulation operation for a wellsite having a reservoir positioned in a subterranean formation, comprising:
- a downhole tool configured to perforate a wellbore of the wellsite; and
- a stimulation tool communicatively coupled to the downhole tool and configured to: generate a log of at least a portion of the wellbore based on data regarding the subterranean formation, wherein the data is acquired via one or more sensors; define a plurality of boundaries at one or more intervals along the log based on the data; identify a plurality of pay zones along the wellbore based on the plurality of boundaries; specify one or more fracture units along the plurality of pay zones, wherein at least one fracture unit of the one or more fracture units comprises two or more pay zones of the plurality of pay zones, wherein the stimulation tool is configured to specify the one or more fractures by: performing one or more height growth estimation calculations for the two or more pay zones of the plurality of pay zones; and determining whether the two or more pay zones of the plurality of pay zones overlap based on the one or more height growth estimation calculations; define one or more stages along the one or more fracture units; design a plurality of perforation locations based on the one or more stages; design a diversion treatment configured to divert fluid from a first perforation location of the plurality of perforation locations to a second perforation location of the plurality of perforation locations; and send a command to cause the downhole tool to: perforate the wellbore at a plurality of locations based on the first perforation location and the second perforation location; and execute the diversion treatment in the subterranean formation.
17. The system of claim 16, wherein the stimulation tool is configured to design a third perforation location of the plurality of perforation locations based on a quality of a pay zone of the plurality of pay zones in which the third perforation location is located.
18. The system of claim 16, wherein the stimulation tool is configured to determine at least one of the plurality of perforation locations based on a product of a permeability and a length of the at least one of the plurality of perforation locations exceeding a threshold value.
19. The system of claim 16, wherein the stimulation tool is configured to specify the one or more fracture units by:
- adjusting the two or more pay zones of the plurality of pay zones based on the one or more height growth estimation calculations to form two or more adjusted pay zones; and
- determining whether the two or more adjusted pay zones overlap.
20. The system of claim 16, wherein the stimulation tool is configured to define two or more of the one or more stages based on a minimum net height, a maximum net height, and a minimum distance between the two or more of the one or more stages.
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Filed: Aug 6, 2015
Date of Patent: Oct 2, 2018
Patent Publication Number: 20160047207
Assignee: SCHLUMBERGER TECHNOLOGY CORPORATION (Sugar Land, TX)
Inventors: Bruno Lecerf (Houston, TX), Dmitriy Usoltsev (Richmond, TX), Timothy L. Pope (Cheyenne, WY), Alejandro Pena (Katy, TX), Tarik Itibrout (Richmond, TX), Xiaowei Weng (Fulshear, TX), Hitoshi Onda (Houston, TX), Philippe Enkababian (Richmond, TX)
Primary Examiner: Hugh Jones
Application Number: 14/819,659
International Classification: G06G 7/48 (20060101); E21B 43/00 (20060101); E21B 43/26 (20060101); E21B 43/17 (20060101); G06G 7/50 (20060101);